Hydraulic anchor well tool

ABSTRACT

A single or multiple bore completion tool for permanent packers set in a well bore, the tool having a hydraulic holddown anchor actuated by zone pressure from below the packer. In the multiple completion version, the hydraulic anchor is automatically released when a tubing string is removed from the well tool.

July 3, 1973 United States Patent 1 91 Crow 0 004 2 22 lN/l/ 6 666 6/666 l Olll 6..

3.166.127 1/1965 Brown et a1. 3,288,218 11/1966 Young Dallas 3,333.63) 8/1967 Page et a1. D essalnd tries In D n T 3.414.058 12/1968 deRochemont... r c a as ex 3.559.732 2/1971 Oct. 13, 1971 L o 0 T L L E w R 0 H C N A w u Amm Mm Y s HmA My 57 [22] Filed:

[21] AppL 188,925 Primary Examiner-David H. Brown Attorney-Robert W. Mayer, William E. Johnson, Jr. and Morgan L. Crow et al.

[57] ABSTRACT A single or multiple bore completion tool for permanent packers set in a well bore, the tool having a hydraulic holddown anchor actuated by zone pressure [52] U.S. 166/120, 166/129, 166/114 [51] Int Cl E2lb 33/122, E2lb 33/129 [58] Field of Search................... 166/120, 129, 212,

from below the packer. In the multiple completion version, the hydraulic anchor is automatically released when a tubing string is removed from the well tool.

9 Clalms, 9 Drawlng Figures [56] References Cited UNITED STATES PATENTS 3,045,754 7/1962 Myers 166/120 3,215,206 l l/l965 Crow 166/120 PATENTEDJULS I975 3.743 016 MOQGAA/ A. CPOW AGZFA/T HYDRAULIC ANCHOR WELL TOOL FIELD OF THE INVENTION The field of this invention relates generally to well tools used in completing single and multiple zone wells and in particular to well tools used in wells wherein the pressure below the packer may sometimes exceed the pressure above the packer. Packers used in well completions can generally be classified into two categories, retrievable and permanent. Retrievable packers as the name implies are generally designed to be completely retrievable or removable from the well bore when operations require. So-called drillable or permanent packers seal and grip the well casing for the life of the packer. These tools generally can only be removed by completely or partially destroying the packer to obtain release and recovery of the packer from the well bore. Removal methods for drillable or permanent packers may vary between drilling the packer with a rock bit to completely disintegrate the tool into small chips, or using special tools which have a tubular cutting portion faced with an extremely hard abrasive material so that only the outer portions of the tool which are in contact with the casing are disintegrated. Drill-able or permanent packers provide a seal surface, usually a seal bore, with which removable well tools, which may be run on tubing or wireline, are sealingly engaged.

Retrievable packers with seal bores are now available. While drillable or permanent packers have been more widely used, it should be understood that the well tool according to this invention could be used with a retrievable packer which provides a suitable seal bore.

In a well completion, the pressure below a packer may exceed the pressure above a packer for many reasons well known to those with skill in the art. Well completion devices that are located in the seal bore of the drillable packer usually have a mechanical shoulder to engage the packer and support the completion device against further relative downward motion through the packer. This shoulder, however, does not support the device against upward movement resulting from a pressure beneath the packer which exceeds the pressure above the packer.

DESCRIPTION OF THE PRIOR ART Numerous prior art devices have been provided in attempts to overcome the problem of pressure below the packer. One prior art device in wide usage is described in US. Pat. Nos. 2,644,524 and 2,737,248, wherein it is taught to use no left turn latches. Such devices engage with axial movement with no rotation and disengage with right-hand rotation, thereby avoiding left-hand rotation which might otherwise result in a loosening of the threaded joints in the tubing string which tighten with right-hand rotation and disengage with left-hand rotation. no left turn latches" are useful in many applications; however, it is not always feasible to rotate the tubing, even to the right.

Another prior art device is disclosed in US. Pat. No. 3,559,732. This device is pressure compensated and locks in a packer to prevent movement of the device relative to the packer as a result of a pressure differential from either direction. This device also has the advantage of being releasable from the packer without rotation. However, the space required for the mechanism in this tool prevents its use in single bore completions requiring a large bore through the tool and in multiple zone completions where two or more passageways are required through the tool.

In multiple completion tools adapted for use with drillable or permanent packers. It is common practice 5 to use a larger bore in the upper packer and succeedingly smaller bores in packers set at deeper depths. This permits seals for the lower packers, which are on the retrievable tubing strings, to pass through upper packers with sufficient clearance to avoid sealing engagement with the upper packers. Such clearance reduces the likelihood of seals being damaged before reaching the seal bore for which they are intended.

Different sizes of seal bores facilitate the placement of seal nipples in position in undamaged condition. However, different sizes of seal bores with the larger bore on top can cause difficulty if the pressure below the upper packer is greater than the pressure above the upper packer. Assuming the pressure below the bottom packer is substantially equal to or greater than the pressure above the top packer, the pressure differentials across the packers act against the seal bore diameters in the packers and result in a net upthrust tending to unseat the seals from the packers.

Attempts to solve this problem in the past have included putting additional tubing string weight on the well tool positioned in the permanent packer seal bore. This tactic, however, has the disadvantage of causing excessive and sometimes permanent buckling of the tubing strings with attendant difficulty in running wireline tools through the tubing strings. The problem in regular single string completions has been solved by using no turn latches. The large diameters involved in multiple completions and the use of parallel tubing strings many times makes this approach unworkable. Also the multiple passages in the completion tools sometimes preclude sufficient space to include such latch mechanism.

U.S. Pat. No. 2,743,781 discloses a hydraulic anchor for holding well tools, such as retrievable well packers against upward movement due to pressure in the tubing and under the packer. This tool is one of the early hydraulic anchors and, since it did not include a valve for equalizing pressure inside and outside the tool, difficulty was sometimes encountered in attempting to release the tool. The tool disclosed includes only a single passage extending therethrough.

US. Pat. No. 3,083,768 discloses a dual completion adapter for a large bore permanent packer. This tool provides communication for the second string through a tubular connection surrounding the first string and connecting a body with two parallel bores to the upper drillable packer. As an example in this patent, in a usual completion, the surrounding tubular connection would need to be on the order of to feet long in order to deflect the first tubing string from an eccentric connection to the first tubing string bore over to a position nearer the center line of the upper drillable packer. This device has the disadvantage of not providing a straight through passageway for the second tubular string and also of having an exceedingly long length which is costly to manufacture.

My US. Pat. No. 3,215,206 discloses a hydraulic anchor useful for multiple string well tools. This patent discloses a retrievable dual string packer with a hydraulic anchor adaptable to placement between the passages of a multiple passage well tool.

None of the prior art devies teach or disclose large bore or multiple passage apparatus which will satisfactorily engage a permanent packer set in a well and hold the apparatus down against the upthrust caused by a pressure differential up across the packer and yet be retrievable without rotation.

It is therefore a primary object of the present invention to provide an improved completion tool for a permanent packer that is releasable without rotation.

Another object of this invention is to provide an improved completion tool for large bore permanent packers, the tool being releasable without rotation.

An additional object of this invention is to provide a multiple completion tool for a permanent packer set in a well casing wherein the completion tool is retrievable without rotation.

It is a still further object of this invention to provide a multiple completion well tool for a permanent packer set in a casing which will automatically release from the well casing upon removal of a tubing string from the well tool.

SUMMARY OF THE INVENTION The objects of the invention are achieved, broadly, by an improved apparatus for use in a packer with a seal bore anchored in a well casing, having a body with a longitudinal bore and one or more lateral bores in communication with the longitudinal bore, a gripping member in each of the lateral bores expandable outwardly against the well casing in response to pressure in the body, and a seal to seal with the packer seal bore. As optional features, the apparatus may have multiple longitudinal bores, and may be adapted to accept plugs in one or more of the longitudinal bores.

BRIEF DESCRIPTION OF THE DRAWING FIGS. 1A and 1B are views, partially in elevation and partially in section, showing a hydraulic anchor well tool constructed according to the invention;

FIG. 2A is a view, partially in section and partially in elevation, of the well tool of FIGS. IA and 1B; with an excess of pressure above the well tool;

FIG. 2B is a view, partially in section and partially in elevation, of the well tool of FIGS. 1A and 18; with an excess of pressure below the well tool;

FIG. 3 is a view, partially in elevation and partially in section, showing another embodiment of a hydraulic anchor well tool also constructed according to the invention;

FIG. 4 is a view taken generally along the line 4-4 of FIG. 3;

FIG. 5 is a view taken generally along the line 5-5 of FIG. 4;

FIG. 6 is a view similar to FIG. 5 illustrating a modified well tool also constructed according to the invention;

FIG. 7 is a schematic view in section illustrating a well completion with a hydraulic anchor well tool according to the invention.

DETAILED DESCRIPTION OF THE SINGLE STRING PREFERRED EMBODIMENT Referring now to FIGS. 1A and 1B, a hydraulic anchor well tool is illustrated generally at 5 as being threadedly connected to tubing 10 by which the tool may be lowered into the well bore. It should be appreciated that FIG. 1A illustrates the upper segment of the tool and FIG. 1B is the lower segment. A packer 14, previously set in a well casing 8, has a seal bore 16 extending upwardly therefrom.

Seals 18 carried by the well tool sealingly engage the seal bore 16 to hold pressure from above the well tool. Seals 20 on the well tool face downwardly and hold pressure from below. Seals l8 and 20, in combination, seal with seal bore 16 and prevent flow in either direction. The mandrel 12, valve 22, and valve seal 24 are movable downwardly as a unit to allow valve seal 24 and valve 22 to engage valve seat 26. Valve 22 is affixed to mandrel 12 by a ring 28 located in groove 30 in mandrel 12. Ring 28 is formed of at least two pieces so that it may be assembled radially into the groove 30. Valve 22 is assembled axially over ring 28 to prevent radial disengagement of ring 28 from groove 30. A retaining ring 32 in a groove located in the internal bore of valve 22 maintains ring 28 in engagement with valve 22 and groove 30 in mandrel 12. A seal 34 which may be of the O-ring type is sealingly disposed between valve 22 and sleeve 36. Balance piston 38 has a seal 40 which may be of the O-ring type also engaging sleeve 36. Hydraulic anchor body 42 has a seal 39 sealingly engaging balance piston 38. Balance piston 38 is slidable in sleeve 36 and hydraulic anchor body 42. Hydraulic anchor body 42 has a seal 44 which may be of the O-ring type engaging mandrel l2. Piston slips 46 are illustrated disposed in lateral bores 48. While the lateral bores 48 as illustrated are cylindrical, they could be of another shape such as square, rectangular, or another shape. Bores 48 are illustrated substantially perpendicular to the mandrel 12; however, the bores 48 could be at a different angle. While a plurality of piston slips 46 and lateral bores 48 are shown, the invention contemplates the use of a single piston slip 46 and lateral bore 48. Seals 50 which may be of the O-ring type sealingly engage the piston slip 46 and the lateral bore 48. A spring 52 is positioned between a retaining strap 54 to urge the piston slip 46 into its retracted position. Strap 54 is attached to the body by suitable fasteners such as screws 56.

The valve seat 26 has threads 58 to which a seal nipple 60 is attached and sealed with a suitable seal 62 such as an O-ring. Threads 64 on the lower end of the seal nipple are used to secure a retaining nut 66 which holds seals 18, 20 and the associated spacers in place. Seals l8 and 20 are in sealing engagement with the outside diameter of seal nipple 60. Seal nipple 60 and mandrel 12 form an annular passageway 68. Pressure from below the packer I4 is conducted through annular passageway 68 past the pickup ring 72 which is slotted to allow passage of the pressure which then may be admitted through the inside diameter of valve seat 26, through the inside diameter of valve 22, through the gaps in split ring 28, through the inside diameter of balance piston 38, through the inside of body 42, to be admitted to piston slips 46 where any difference in pressure from the inside of body 42 toward the outside of body 42 will act against the back of piston slips 46 and force each one into contact with the inside of the easing. The total area of the piston slips against which the be forced upward against the hydraulic anchor body 42. This excess of pressure will then act downwardly on the top side of valve 22 which is sealed with valve seal 24 and O-ring 34. This excess of pressure from below the packer will then hold the valve 22 in a sealed position. The split ring 28 engaged with mandrel 12 will then hold these associated parts against upthrust from the excess of pressure below the packer. Port 70 in the sleeve 36 admits pressure from above the packer to the upper side of piston 38 and allows flow to cause piston 38 to move from its extreme upward position to the extreme downward position according to the direction of the pressure differential from above or below the packer.

An excess of pressure above the packer greater than the pressure below the packer will cause piston slips 46 to retract to their extreme inward position out of contact with the casing. This pressure will also be admitted through port 70 to the upper side of piston 38 which will then move down into contact with valve 22. The excess of pressure above the packer acting upwardly on valve 22 outside the seal diameter 24 will then be balanced by the same pressure entering through port 70 thrusting piston 38 in a downward direction.

The tubing is threadedly connected to mandrel 12 by coupling 12a. Valve 22 is assembled in fixed axial relation to mandrel 12 by split ring 28 located in groove 30 in mandrel 12. A bore in valve 22 is assembled axially over ring 28 to hold ring 28 in radial engagement with groove 30. A retaining ring 32 in the same bore of valve 22 holds valve 22 locked axially on ring 28 and in fixed axial relation to mandrel 12.

Sleeve 36 is threadedly engaged to anchor body 42. Anchor body 42 and sleeve 36 are slidable axially on the mandrel 12 and valve 22. O-ring 44 sealingly engages anchor body 42 and mandrel 12. O-ring 34 sealingly engages valve 22 and sleeve 36. Balance piston 38 is slidable axially with anchor body 42 and sleeve 36. A seal 40 which may be of the O-ring type is sealingly disposed between balance piston 38 and sleeve 36. A seal 39 which may be of the O-ring type is sealingly disposed between the balance piston 38 and anchor body 42.

A pickup ring 72 is slidable axially on mandrel l2 and shoulders against shoulder 74 on mandrel 12. Pickup ring 72 supports an internal shoulder on valve seat 26. Valve seat 26 is threadedly engaged by threads 58 to seal nipple 60 which is connected by threads 64 to retaining nut 66. Seals 18 and seals and the associated spacers are held in place by retaining nut 66. Annular passageway 68 is formed between seal nipple 60 and mandrel 12. Communication with passageway 68 is provided through slots in pickup ring 72 to the inside diameter of valve seat 26 to allow flow therethrough. The pressure above valve 22 acting downwardly will hold the mandrel in position. Upstrain may be applied to the tubing 10 to move the mandrel 12 upwardly, because the force acting downwardly against valve 22 will be substantially counterbalanced by an upthrust caused by the excess of pressure below the packer pushing up against the area of the mandrel against which seal ring 44 is sealed. With an excess of pressure below the packer, the mandrel may be moved upwardly to move valve seal 24 out of engagement with the valve seat 26 to allow flow between valve 22 and valve seal 24 and through port 27 to equalize the pressure above and below the packer. With the pressures equalized, the

force urging each piston slip 46 against the casing 8 will be removed so that the piston slips 46 will disengage from the casing to allow the tool to be withdrawn from the well bore permitting the seal nipple 60 and the associated seals 18 and 20 to be removed from the packer set in the casing so that the retrievable portions of the tool may be retrieved when desired, leaving the permanent packer 14 with seal bore 16 in place.

FIG. 2A is an illustration of the apparatus in FIG. I in engaging position with a drillable packer 14 set in the casing 8. In FIG. 2A, piston 38 is illustrated in the down position against valve 22 as these parts are located when an excess of pressure above the packer is admitted through port 70 to force piston 38 down against valve 22.

In FIG. 2B, piston 38 is illustrated in its up position where it moves in response to an excess of pressure below the packer greater than the pressure above the packer. Piston slip 46 is illustrated in contact with the casing. Teeth 47 are sharp, hardened teeth to grip the casing.

OPERATION OF THE SINGLE STRING PREFERRED EMBODIMENT The permanent packer 14 is set in the well casing 8 at the appropriate depth by means of a wireline setting tool or by a tubing setting tool in ways that are well known to those with skill in the art. The packer 14 is thereby anchored and sealed to the casing. The seal bore 16 in the packer 14 is then in position to receive a suitable well tool. The preferred single string embodiment according to this invention is connected to the well tubing 10 and lowered into the casing to a depth so that the seals 18 and 20 fully enter into the seal bore 16. The tubing 10 is lowered still further to lower mandrel 12 and valve 22 attached to mandrel 12 in the manner hereinbefore described. Until valve seal 24 sealingly engages valve seat 26, the hydraulic anchor body 42 and sleeve 36 move down with the mandrel until the lower end of sleeve 36 engages valve seat 26. Valve 22 and mandrel 12 continue to move downwardly until the valve seal 24 sealingly engages valve seat 26.

Referring to FIG. 2A, the well tool with an excess of pressure above the packer greater than the pressure below the packet will assume the position shown. The piston slips 46 will remain in the retracted position due to the greater pressure outside the tool holding the slips in the retracted position closest to the mandrel 12. The excess of pressure above the packer will enter port 70 and cause balance piston 38 to move downwardly and engage valve 22. The same pressure will enter port 27 and act upwardly on the lower side of valve 22. Balance piston 38 is designed so that the area exposed to pressure entering port 70 will be approximately equal to or greater than the area on the lower side of valve 22 which is exposed to the same pressure. The thrust generated on the balance piston 38 and the valve 22 will simply cause the balance piston to shoulder against valve 22 so that any net unbalance of force is downward, tending to hold valve 22 down against the valve seat 26 in sealing engagement.

Referring to FIG. 28, when there is an excess of pressure below the packer greater than the pressure above the packer, fluid pressure is conducted in the annular passageway external of the mandrel 12 through packer 14, through the inside diameter of seal nipple 60,

through the slots in the pickup ring 72 and through the inside diameter of valve seat 26 and valve 22. Pressure is conducted through the axial slots in split ring 28, through the inside diameter of balance piston 38 and into the inside diameter of hydraulic anchor body 42 and is admitted to the mandrel side of piston slips 46 thrusting the piston slips 46 against the casing causing the piston slip teeth to engage and grip casing 8. The piston slips 46 are sized so that pressure forcing them against the casing 8 will generate sufficient grip with teeth 47 to hold down hydraulic anchor body 42 which is anchored to the casing 8 by piston slips 46 to resist all upward movement of the remainder of the well tool.

Pressure acting upwardly on the bottom of seal nipple 60 causes a force which is transmitted through valve seat 26 to sleeve 36 to hydraulic anchor body 42 to piston slips 46 and to casing 8. Pressure from below is admitted external of the mandrel 12 in the annular passageway formed by the packer 14 and the other parts of the well tool. This pressure is admitted to the chamber formed on the upper side by balance piston 38 and on the lower side by valve 22 contained externally by sleeve 36 and internally by the mandrel 12. The excess of pressure acting downwardly on the top of valve 22 holds valve 22 down in engagement with valve seat 26. The pressure thrusting upwardly on the lower end of balance piston 38 causes the balance piston 38 to move upwardly against the lower end of hydraulic anchor body 42 where the pressure acting against the sealed area of balance piston 38 creates a force upwardly which is held by piston slips 46 against the casing 8 in the manner hereinbefore described.

A significant advantage of the single string preferred embodiment of the tool according to this invention is that with a differential pressure with the excess pressure below the packer the tubing can be lifted, allowing the mandrel 12 and valve 22 to move upwardly with respect to valve seat 26 and hydraulic anchor body 42 releasing valve seat 24 from valve seat 26 and allowing the differential pressure to be equalized through the valve and through the ports 27. Once the differential pressure is equalized, piston slips 46 release the grip to the casing 8 and the complete tool may be withdrawn from the seal bore 16 and from the well.

In a like manner, if a differential pressure with the excess pressure above the packer exists, the tubing 10 and mandrel 12 can be lifted opening the valve and allowing pressure to equalize in the manner just described.

A well tool according to this invention is engageable with a permanent packer and grips the casing for hold down force, and provides the ability to equalize a pressure differential from either above or below the well tool and provides the ability to subsequently release the well tool.

DETAILED DESCRIPTION OF THE MULTIPLE STRING PREFERRED EMBODIMENT Referring to FIG. 3, there is illustrated a multiple string embodiment of apparatus according to this invention. A hydraulic anchor well tool is illustrated threadedly connected to tubing 210 with which the tool is lowered into the well bore. A permanent packer bore 216 to prevent flow in either direction. Once the tool is lowered to position and the seals 218 and 220 engage the seal bore 216, body is in the set position. A longitudinal bore 102 through the body communicates with the tubing 210 above the tool and tubing 104 below the tool which may extend to another packer set at a lower depth in the casing as will be further described and as further illustrated in FIG. 7. Body 100 has a second parallel longitudinal bore 106 that has in its upper end a seal bore 108 into which a seal assembly or seal nipple 110 which has chevron seals 112 facing upwardly and chevron seals 114 facing downwardly to prevent flow in either direction past seal nipple 110. This assembly has a combination retaining nut and collet 116. The collect 116 has longitudinal slots 118 and an enlarged ring diameter 120 intermediate the length of slots 118 so the collect may be deflected inwardly past bore 122 which is smaller than the enlarged ring 120 so that upon inserting of seal nipple 110 into seal bore 108 an indication of such penetration will be transmitted to the surface of the well bore upon deflection of enlarged diameter 120 into bore 122. Bore 124 is large enough to permit enlarged ring 120 to enlarge to its relaxed diameter. The collect 116 then assists in holding the seal nipple 110 in position due to the predetermined force required to compress enlarged section 120 to the smaller diameter of bore 122 before seal nipple 110 can be withdrawn from the seal bore 108. Sea] nipple 1 10 is connected by threads 126 to tubing string 128 which is run parallel to tubing string 210 inside of casing 208. Tubing string 128 extends to the surface of the well bore for conducting fluid from an upper zone through bore 106 then through seal nipple 110 to tubing string 128 where the production is then conducted to the surface of the well bore as will be more completely described and illustrated in FIG. 7. A scoop 130 with a conical upper surface 132 may be used to guide the lower end of collect 116 into seal bore 108 so the seal nipple 110 may be lowered into sealing engagement with seal bore 108.

FIG. 4 is a top view taken along section lines 44 in FIG. 3 illustrating the positions of tubing strings 210 and 128. The scoop 130 is connected to body 100 by suitable fasteners such as screws 134.

FIG. 5 is a section of FIG. 3 taken through offset section lines 5-5 illustrated in FIG. 4, illustrating a cross section through the body 100. Piston slips 146 are positioned in bores 148 in the manner described in the embodiment illustrated in FIG. 1.

The left side of FIG. 5 illustrates a way of porting piston slips 146 to the second longitudinal bore 106. Ports 150 are drilled from the piston slip bores 148 into the bore 124 which is a continuation of the second longitudinal bore and is in communication with bore 106.

On the right side of FIG. 5 an alternative porting arrangement is illustrated. Passage 152 may be formed by drilled holes from bores 148 to intersect and communicate an upper piston slip bore 148 with the lower piston slip bore 148. The single port 154 may be drilled from a piston slip bore 148 into the second longitudinal passage as illustrated by bore 106. The port 154 may then communicate pressure within the second bore 106 to all of the piston slip bores on that side of a tool.

FIG. 6 illustrates an alternative embodiment according to this invention. The piston slip bores 148' are communicated by a passage 152' as illustrated in FIG. 5. A passage 156 may be drilled to communicate the piston slip bore with pressure below body 158. A conventional wireline retrievable plug 160 may be set in a suitable profile in bore 106' designed to receive a commercially available plug which can be latched and sealed in a suitable contour provided in the longitudinal bore 106'. The plug can be positioned and latched in sealing engagement by use of a wireline operated from the surface of the well bore in a manner well known to those of ordinary skill in the art. The plug can also be retrieved by use of the wireline. With this arrangement, the wireline plug 160 may be positioned in sealing engagement in bore 106'. Pressure from below body 158 is communicated to piston slips 146 in bores 148' through passages 156 and 152'. Not shown in FIG. 6 but illustrated in FIG. 7, a tubing string may be connected to the body by an ordinary tubing thread or an easily releasable thread such as a left hand thread.

FIG. 7 illustrates a dual completion with apparatus according to this invention. A lower packer 13 may be positioned in casing 208' between the upper zone 9 and the lower zone 7. The upper packer 214' is anchored and sealed at the proper depth in casing 208. An upper producing zone 9 may be drained into casing 208 through perforations 11. A suitable seal nipple 15 may be used to seal against the seal bore 17 in packer 13. The lower zone 7 drains into the casing through perforations 19 and enters the lower end of seal nipple 15 and is conducted through the tubing 104 through longitudinal bore 102' in the parallel string hydraulic anchor body 158 and from there is conducted through tubing 21010 to the surface of the well bore. Tubing 210 may be connected to the body 158 by the connection 164 which can be an ordinary tapered tubing thread, but as an optional feature may be a left hand thread or other means to facilitate release and recovery of tubing string 210', while leaving the remainder of the equipment in place in the well.

A plug 160 which may be positioned and retrieved by a wireline as shown in longitudinal bore 106' is shown schematically as was described in detail in connection with FIG. 6. Plug 160 may be positioned and latched in sealing engagement with longitudinal bore 106' to permit removal of tubing string 128 without positioning a weighted fluid in tubing string 128 and causing 208' with the attendant advantages hereinbefore described.

OPERATION OF THE DUAL STRING PREFERRED EMBODIMENT Referring to FIG. 7, the sequence of operation is as follows. A lower packer 13 would be run and set in the casing in a manner hereinbefore described at the location between lower zone 7 and the upper zone 9. The packer 13 has a seal bore internally to receive a seal nipple to be run later. An upper packer 214' is run and set in a manner hereinbefore described. A tubing string is made up with a seal nipple being lowered into the casing first, then a suitable length of the tubing 104', the body 158 of the well tool according to this invention; then a suitable quantity of tubing 210 is added to lower the entire assembly to setting depth. The dual string well tool body is lowered into a seal bore 216' of packer 214 into sealing engagement. The length of tubing 104' below body 158 locates seal nipple 15 in sealing engagement with the seal bore 17 in the lower packer. The seal assembly 110' is then lowered into the well on a suitable quantity of tubing 128 to engage seal nipple 110' with the seal bore 108' in the body 158.

With the equipment in position as described, the lower zone may be produced through the perforations l9 and into the interior of seal nipple 15 and conducted to the surface of the well bore through tubing 104', longitudinal bore 102 and tubing string 210'.

Upper zone production can enter the well casing 208' through perforations 11 and enter longitudinal bore 106' in body 158 where it is conducted to the surface of the well bore through seal nipple 110 and tubing string 128.

With the piston slips ported directly to pressure below packer 214' as illustrated in FIG. 6 or ported to pressure below packer 214 through longitudinal bore 106' as illustrated in FIG. 5, any excess of pressure below the packer 214' exerts an upward thrust on the body sealed in seal bore 216 as illustrated in FIG. 7. The body 158 is held against upward movement by the grip of the piston slips being thrusted against the casing by the same pressure tending to thrust the body upward of the seal bore.

Referring to FIG. 3, the equipment is removed from the well by lifting tubing 128 to remove seal nipple 110 from seal bore 108. Any pressure differential across body is equalized through seal bore 108 and longitudinal bore 106. Tubing 128 and seal nipple are completely removed from the well bore. Tubing 210 is lifted to remove body 100, tubing 104 and all connected parts from the well bore, leaving packer 214 in place.

OPERATION OF THE DUAL STRING ALTERNATE EMBODIMENT Referring to FIG. 7, the completion equipment may be provided with suitable receptacles in longitudinal bores 102' and 106 to accept plugs which can be positioned by wireline from the surface of the well bore.

Use of the plug 160 in the longitudinal bore 106' below seal assembly 110 to contain an excess of pressure below the body 158 so that tubing string 128 with seal nipple 110' can be withdrawn from the well to reposition, repair or replace equipment in the tubing string such as gas lift valves. The plug 160 in the bore seals the pressure and eliminates the necessity of killing the well by pumping a fluid of sufficient weight into the tubing and casing so that the pressure in the zone is overcome. Killing a well is undesirable from several standpoints. The cost of the mud or other weighted fluid is an important factor. Also, such a fluid can sometimes enter a producing zone and cause the small passages through which oil and/or gas flows to the well bore to become plugged from solid materials in the weighted fluid or the weighted fluid may cause an adverse chemical reaction causing the formation itself to swell, reducing the flow area of the passages leading to the well bore. Use of the plug 160 eliminates the need for killing the well and thereby eliminates many of the attendant disadvantages.

Tubing string 210 may be removed to reposition, add, move, repair or replace equipment in the tubing string such as gas lift valve without having to kill the well. Connection 164 may also be a releasable connection which forms a mechanical connection and also forms a seal between tubing 210' and body 158. A plug 166 is positioned by wireline in a suitable receptacle in longitudinal bore 102' to plug the passage. The tubing 210' may then be disconnected from body 158 at connection 164 after the plug is positioned, leaving the body and tubing string 128' in place. Flow from zone 7 is prevented, making it possible to remove tubing 210' without positioning a weighted fluid in the casing 208' and tubing 210' to hold down the pressure in zone 7.

The embodiments of the invention in which an exclusive property or privilege is claimed are defined as follows:

1. In apparatus adapted for use in a packer with a seal bore anchored in a well casing, the improvement comprising:

a body having a longitudinal bore and a lateral bore therein in communication with said longitudinal bore;

a gripping member in said lateral bore expandable outwardly against the well casing in response to fluid pressure within said body and said lateral bore;

a seal sealingly engageable between said body and the seal bore in the packer;

a mandrel in said longitudinal bore and slidable in said body, and forming an annular passageway in said body; and

valve means for selectively opening and closing said annular passageway upon relative movement of said mandrel with respect to said body.

2. Apparatus according to claim 1 further comprising means responsive to pressure in said annular passageway for exerting a downward force on said mandrel.

3. ln apparatus adapted for use in a packer with a seal bore anchored in a well casing, the improvement comprising:

a body having a longitudinal bore and a plurality of lateral bores in communication with said longitudinal bores;

a plurality of gripping members, one of said plurality of gripping members being in each said lateral bore and expandable outwardly against the well casing in response to fluid pressure within said body and each said lateral bore;

a seal sealingly engageable between said body and the seal bore in the packer;

a mandrel in said longitudinal bore and slidable in said body, and forming an annular passageway in said body; and

valve means for selectively opening and closing said annular passageway upon relative movement of said mandrel with respect to said body.

4. Apparatus according to claim 3 further comprising means responsive to pressure in said annular passageway for exerting a downward force on said mandrel.

5. In multiple zone subsurface well production apparatus adapted for use with an upper packer and a lower packer each anchored in a well casing, and first and second tubular strings extending to the top of a well bore, the improvement comprising:

a body having a first and a second longitudinal bore communicating with said first and second tubular strings respectively, and a plurality of lateral bores;

casing gripping members sealingly and slidingly disposed in said lateral bores;

a seal sealingly engageable between said body and the upper packer; and

passage means communicating said lateral bores with one of said longitudinal bores.

6. In multiple zone subsurface well production apparatus adapted for use with an upper packer and a lower packer each anchored in a well casing, and first and second tubular strings extending to the top of a well bore, comprising:

a body having a first and a second longitudinal bore communicating with said first and second tubular strings respectively, and a plurality of lateral bores;

casing gripping members sealingly and slidingly disposed in said lateral bores;

a seal sealingly engageable between said body and the upper packer; and

passage means communicating said lateral bores with the lower end of said body.

7. Apparatus according to claim 6 further compris closable means in said second longitudinal bore for selectively preventing communication through said second longitudinal bore.

8. Apparatus according to claim 6 further comprisreleasable means in said first longitudinal bore for selectively connecting and communicating said first tubular string with said first longitudinal bore.

9. Apparatus according to claim 8 further comprisclosable means in said first longitudinal bore for selectively preventing communication through said first longitudinal bore. 

1. In apparatus adapted for use in a packer with a seal bore anchored in a well casing, the improvement comprising: a body having a longitudinal bore and a lateral bore therein in communication with said longitudinal bore; a gripping member in said lateral bore expandable outwardly against the well casing in response to fluid pressure within said body and said lateral bore; a seal sealingly engageable between said body and the seal bore in the packer; a mandrel in said longitudinal bore and slidable in said body, and forming an annular passageway in said body; and valve means for selectively opening and closing said annular passageway upon relative movement of said mandrel with respect to said body.
 2. Apparatus according to claim 1 further comprising means responsive to pressure in said annular passageway for exerting a downward force on said mandrel.
 3. In apparatus adapted for use in a packer with a seal bore anchored in a well casing, the improvement comprising: a body having a longitudinal bore and a plurality of lateral bores in communication with said longitudinal bores; a plurality of gripping members, one of said plurality of gripping members being in each said lateral bore and expandable outwardly against the well casing in response to fluid pressure within said body and each said lateral bore; a seal sealingly engageable between said body and the seal bore in the packer; a mandrel in said longitudinal bore and slidable in said body, and forming an annular passageway in said body; and valve means for selectively opening and closing said annular passageway upon relative movement of said mandrel with respect to said body.
 4. Apparatus according to claim 3 further comprising means responsive to pressure in said annular passageway for exerting a downward force on said mandrel.
 5. In multiple zone subsurface well production apparatus adapted for use with an upper packer and a lower packer each anchored in a well casing, and first and second tubular strings extending to the top of a well bore, the improvement comprising: a body having a first and a second longitudinal bore communicating with said first and second tubular strings respectively, and a plurality of lateral bores; casing gripping members sealingly and slidingly disposed in said lateral bores; a seal sealingly engageable between said body and the upper packer; and passage means communicating said lateral bores with one of said longitudinal bores.
 6. In multiple zone subsurface well production apparatus adapted for use with an upper packer and a lower packer each anchored in a well casing, and first and second tubular strings extending to the top of a well bore, comprising: a body having a first and a second longitudinal bore communicating with said first and second tubular strings respectively, and a plurality of lateral bores; casing gripping members sealingly and slidingly disposed in said lateral bores; a seal sealingly engageable between said body and the upper packer; and passage means communicating said lateral bores with the lower end of said body.
 7. Apparatus according to claim 6 further comprising: closable means in said second longitudinal bore for selectively preventing communication through said second longitudinal bore.
 8. Apparatus according to claim 6 further comprising: releasable means in said first longitudinal bore for selectively connecting and communicating said first tubular string with said first longitudinal bore.
 9. Apparatus according to claim 8 further comprising: closable means in said first longitudinal bore for selectively preventing communication through said first longitudinal bore. 